There is an ongoing need in the oil and gas exploration industry, and other industries, to control fluid (e.g., oil and water) and gas flow from within wells or other earthen formations at a wellsite. A “well” means or refers to a hole that is drilled to access producing formations to allow the exploration and recovery of natural resources such as oil, gas or water. A “wellbore” means or refers to the actual hole that forms the well. The wall or walls of the well define the wellbore “face.” The wellbore and wellbore face can be encased by materials such as steel and/or cement, or the well walls may be uncased. By way of example, a wellbore may be drilled in any suitable orientation including vertical, horizontal and/or angled and can include a combination of vertical, horizontal and angled portions.
Settings in which containment of fluid and gas flow is required include, for example, drilling of new wells, re-drilling of existing wells and workover operations.
When a new well is drilled, a drilling fluid is used to control subsurface pressures. In unusual circumstances, such as total loss of the drilling fluid, attempts may be made to use cement. In certain applications, the cement can be used to provide a type of covering or “sheath” encasing the wellbore face. The cement covering is intended to seal the wellbore face and prevent fluid and gas flow therethrough. In other applications, cement can be used to secure casings within the wellbore and to provide a fluid-and-gas tight barrier between the casings and the surrounding formation.
Care must be taken not to damage the earthen formation, particularly when drilling a well in the “production zone” of the formation. The production zone refers to the portion of the formation from which fluids and/or gas are to be extracted.
Conventional Portland-type cements are frequently used to cover the wellbore face or to secure a production liner within the production zone. Such Portland-type cements are pumped into the wellbore as flowable slurry and displaced into the external annulus of the casing liner to cement the production liner into the formation. In upper casing sections above the production liner, the cement, particularly at the cement “shoe,” can be drilled out to allow further drilling as the well progresses. The production liner and cement can subsequently be perforated to allow fluid and gas to flow into the production liner.
A problem with the use of Portland-type cements for these and other types of wellbore applications is that such cements tend to have a relatively slow and unpredictable transition from a flowable slurry to a solid state. While in the flowable slurry state, the Portland-type cement can migrate back into the earthen formation around the wellbore. Such migration can be a particular problem in the production zone because the cement can fill cavities deep within the formation blocking flow of fluid and gas to the production liner and potentially requiring costly remedial operations to restore oil and gas flow from the formation.
A further problem with Portland-type cements is that the relatively slow transition of the cement from flowable slurry to solid state can cause such cements to form an incomplete barrier to fluid and gas flow into the wellbore, thereby permitting fluids and gas to pass through the cement in an uncontrolled manner. This problem is referred to as “channeling.”
By way of example, Portland-type cement is frequently used to secure a surface casing within the well at what is known as the casing shoe. At the casing shoe, a surface casing end distal to the surface of the wellsite is encased in cement. This volume of cement is displaced out of the casing by “dropping a ball”, which is drillable, on top of the cement. The ball is then pumped down to the casing shoe with drilling fluid. Once hardened, the ball, shoe and cement is drilled out. An inner casing can then be extended through the outer casing and past the casing shoe deeper into the well.
While the cement around the casing shoe is in the flowable slurry state, hydrostatic pressure exerted by the drilling fluid prevents fluid and gas flow through the cement. However, when the cement transitions from flowable slurry to the solid state, it forms a “gel” which provides the cement with a slight strength. The slight strength of the cement reduces the hydrostatic pressure on the formation thereby allowing fluids and gas to pass through, or channel through, the cement resulting in the channeling problem. The channeling creates small holes and voids through which fluid and gas can pass through the cement. The channels formed in the cement persist after the cement hardens to the solid state. The channels cause the cement to provide an incomplete barrier between the formation and the wellbore so that fluid and gas can pass vertically or horizontally through the cement, exterior to the casing and migrate through the formation exterior to the casing in an uncontrolled manner. This uncontrolled flow of fluid and gas into the well represents a problem for the well operator.
Existing wells are frequently re-drilled to extract additional oil and gas from the earthen formation around the wellbore. “Tight oil” is a term used to describe re-drilling of existing vertical wells in a horizontal direction, especially under conditions of low reservoir porosity and permeability. In underbalanced or unpressurized wells in which oil will not flow because of the lack of formation pressure the wells must be pumped by mechanical means to lift the oil to the surface. Horizontal drilling of old wells can advantageously open the reservoir to further exploitation by greatly increasing the productive area of the formation which is exposed to the wellbore. Many of these re-drilled wells are hydraulically fractured to open the formation even further so as to better access the oil and gas in the formation.
As described previously, it is of particular importance that the cement used to secure casings and the production liner within the production zone does not flow into and damage the production zone. Unwanted migration of cement into the formation can be a particular problem in tight oil applications in which the underbalanced or unpressurized formation does not provide a force resisting cement migration into the formation.
In workover operations, such as replacing corroded or damaged production tubing, the well operator is required to completely seal the wellbore to contain all oil and gas in the well. This containment must be completed before the wellhead or blow out preventer (BOP) can be removed to perform the workover repairs. Complete containment of oil and gas in the well is referred to as “killing” the well because oil and gas cannot flow through the wellbore to the earth surface at the well site.
The complete sealing of the wellbore to contain the oil and gas in the well is frequently accomplished by use of a polymerized brine which hydrostatically overbalances any formation pressure in the reservoir. This fluid is typically a polymerized calcium carbonate brine. The column of brine in the wellbore provides the hydrostatic force.
A disadvantage of the fluids used for this purpose is that the hydrostatic pressure can force the fluid back into the earthen formation around the wellbore. This hydrostatic pressure must be greater than the formation pressures it is designed to contain. This is termed “overbalance.” Workover fluids are intended to prevent this fluid invasion into the earthen formation by including a particulate constituent, usually calcium carbonate, into the fluid. As the polymerized fluid is forced back into the formation by hydrostatic pressure the calcium carbonate particulates “screen-out” at the wellbore face. The calcium carbonate forms a “cake” along the wellbore face which is intended to block fluid invasion into the earthen formation.
In actual practice, the calcium carbonate cake is continuously eroded by the dynamics of circulating the drilling fluid within the well to remove unwanted debris and particulates and to keep the calcium carbonate brine clean. And, the running in and out of the wellbore of various tools and new production tubing, etc. contributes to the erosion. This continuous erosion and deposition cycle means that polymerized brine is forced outwardly from the wellbore into the earthen formation as the calcium carbonate cake is eroded and redeposited. The potential for damage to the production formation under these circumstances is high. Once the workover is completed and the well is brought back into production, wells with positive formation pressure will attempt to “flow back” this polymerized filtrate into the well. In reservoirs with high porosity/permeability characteristics the operator of the well may be able to clear the formation of the invasive fluid minimizing any residual damage. However, in underbalanced wells, positive formation pressure is lacking and this lack of pressure permits polymerized brine drilling fluid to flow away from the wellbore and into the reservoir. The greater the porosity or permeability of the reservoir, the further back into the earthen formation the polymerized brine drilling fluid may flow. If the polymerized brine drilling fluid flows into the earthen formation to a significant extent, then oil and gas flow from the formation may be blocked by the polymerized brine drilling fluid which in an oil well can form an emulsion within the formation potentially requiring costly remedial operations to restore oil and gas flow from the formation.
Cost is another potential disadvantage of drilling fluids. As an example, calcium bromide brine is particularly expensive and potentially hazardous to the environment.
In other workover settings, it may be necessary to repair damage to casings and other structure used to line the well walls. Any damage to the casings can permit unwanted oil and gas to flow through the casings to the surface around the well site. As previously described, casings are frequently set in place within the wellbore by means of cement. Also as mentioned previously, an endemic problem with Portland-type cements is the formation of gels between the fluid and the set state which can result in the formation of channels in the set cement. Oil and gas from the formation can be forced through any such cracks, into the casings and out of the well either through the casings, or, external to the casing through the formation. This can cause pressure to build up between casings as the oil or gas can be trapped above the problem point. Casings can also corrode over time allowing fluids and gas to enter, or exit the corroded casings in an uncontrolled manner. It can also allow influx of the external formation. This can be particularly troublesome where corroded casing allows the influx of sand into the wellbore. Sand can block the wellbore.
Portland cements and magnesium oxysulfate cements have been utilized in workover operations and drilling operations in an effort to remediate these problems. Magnesium oxysulfate cement is limited to one product formerly known as Magnaplus™ which is sold by the Baker Hughes Company. Magnaplus was originally designed to “convert” in-situ drilling fluid into placement through addition of magnesium sulfate into a magnesium-based drilling fluid. However, these materials have proven to be less than satisfactory because both Portland cement and magnesium oxysulfate cement formed in this way, have an extended gel state before hardening which permits oil and gas to form channels and passages in the hardened cement as previously described. Gel strength generation and the resultant channel formation is an important disadvantage which affects the use of Portland cements and magnesium oxysulfate cements for use in drilling new wells, re-drilling existing wells and workover and remedial operations. Furthermore, allowing the influx of high gel oxysulfates into the production zone where they set and generate compressive strengths, is potentially disastrous as the oxysulfates cannot be removed from the production zone. Although oxysulfates are acid soluble, they must be able to be contacted by the acid to be removed. If the oxysulfate material is too far back in the formation, it cannot be contacted by the acid. A further disadvantage of converting an in situ fluid to a cement is that the wellbore operator would incorporate all the particulate and drilling debris into the cement providing the potential for even greater damage.
Magnesium oxychloride cements have been proposed for use in wellbore operations. See U.S. Pat. No. 6,664,215 (Tomlinson). While excellent for the intended purpose, magnesium oxychloride cements have certain limitations. Magnesium oxychloride chemistry requires preparation of the cement with a concentrated brine. And, the magnesium oxide and chloride ion ratios are only variable within a very narrow range. Magnesium oxychloride cements have utilized relatively low reactivity magnesium oxides because of the lack of controllability of the set point with higher reactivity oxides. This leads to a slower set and the potential for formation of gels. It would be desirable to permit the use of high reactivity magnesium oxides which have better performance.
It would be an improvement in the art to provide an improved composition and methods for limiting, or preventing, the influx of fluids and/or gas into the wellbore from the surrounding formations, which would be noninvasive, which would have predictable and controllable physical properties capable of permitting engineered application of the composition in a variety of environments and conditions and which would avoid the generation of gels and channeling between the flowable and solid states of the composition.